4D seismic as a method for characterizing fracture network and fluid distribution in unconventional reservoir

Patent metadata

Field	Value
Publication number	US-11933929-B2
Application number	US-201916268852-A
Country	US
Kind code	B2
Filing date	Feb 6, 2019
Priority date	Feb 6, 2018
Publication date	Mar 19, 2024
Grant date	Mar 19, 2024

Abstract

A method of characterizing a subterranean formation using a plurality of seismic acquisitions includes obtaining a first seismic acquisition of the subterranean formation, wherein the first seismic acquisition is a baseline survey. Injecting a gas fluid into the subterranean formation, wherein the gas fluid at least partially fills a portion of a fracture network of the subterranean formation. Obtaining a second seismic acquisition of the subterranean formation. Calculating a time-lapse difference in the plurality of seismic acquisitions.

First claim

The invention claimed is:

1. A method of characterizing a subterranean formation:
obtaining a first seismic acquisition of the subterranean formation, wherein the first seismic acquisition is a baseline survey, an initial completion being performed in the subterranean formation after the first seismic acquisition and an enhanced oil recovery operation being performed, the initial completion inducing a fracture network, the enhanced oil recovery operation including injection of a gas fluid into the subterranean formation, and the gas fluid at least partially filling a portion of the fracture network;
obtaining a plurality of second seismic acquisitions of the subterranean formation during the enhanced oil recovery operation, wherein each of the plurality of second seismic acquisitions is respectively captured following a cycle in the enhanced oil recovery operation;
calculating a time-lapse difference between the first seismic acquisition and one of the plurality of second seismic acquisitions;
determining a fluid contact parameter of the gas fluid injected during the enhanced oil recovery operation based on the time-lapse difference between the first seismic acquisition and the one of the plurality of second seismic acquisitions acquired during the enhanced oil recovery operation, the fluid contact parameter being at least one of a contact area or a contact volume; and
determining an injection conformance along a lateral of the subterranean formation based on the fluid contact parameter.

2. The method of claim 1 , wherein the gas fluid is a gas injection fluid.

3. The method of claim 1 , wherein the gas fluid has a gas saturation greater than about three percent in the portion of the fracture network.

4. The method of claim 1 , wherein the gas fluid includes gas selected from a group comprising: carbon dioxide, nitrogen, natural gas, and any combination thereof.

5. The method of claim 1 , wherein at least one of the first seismic acquisition or the plurality of second seismic acquisitions is 3D seismic acquisition.

6. The method of claim 1 , further comprising:
injecting a second gas fluid into the subterranean formation following the plurality of second seismic acquisitions; and
obtaining a third seismic acquisition of the subterranean formation.

7. The method of claim 6 , wherein the fracture network undergoes a period of pressure depletion before the injecting of the second gas fluid.

8. The method of claim 6 , further comprising:
during a well-intervention for production optimization, injecting a third gas fluid into the subterranean formation; and
obtaining a fourth seismic acquisition.

9. The method of claim 1 , wherein the fluid contact parameter is obtained based on an image of fracture zones within seismic resolution.

10. The method of claim 1 , further comprising:
determining a stimulated rock volume of the subterranean formation using the time-lapse difference obtained by calculating difference between a processed baseline seismic survey and a processed monitor seismic survey acquired after the injection of the gas fluid to obtain an image of a fractured stimulated rock volume.

11. The method of claim 1 , wherein the plurality of second seismic acquisitions are obtained approximately within 6 months, 9 months, 12 months, or 15 months.

12. The method of claim 1 , wherein the time-lapse difference is root mean square amplitude difference.

13. A method of characterizing a subterranean formation using a plurality of seismic acquisitions:
obtaining a baseline seismic acquisition of the subterranean formation, an initial completion being performed in the subterranean formation after the baseline seismic acquisition and an enhanced oil recovery operation being performed, the initial completion inducing a fracture network, the enhanced oil recovery operation including injection of a gas fluid into the subterranean formation, and the gas fluid at least partially filling a portion of the fracture network;
obtaining one or more time-dependent seismic acquisitions of the subterranean formation following a cycle in the enhanced oil recovery operation;
calculating a time-lapse difference between the baseline seismic acquisition and one of the one or more time-dependent seismic acquisitions acquired during the enhanced oil recovery operation;
determining a fluid contact parameter of the gas fluid injected during the enhanced oil recovery operation based on the time-lapse difference, the fluid contact parameter being at least one of a contact area or a contact volume; and
determining an injection conformance along a lateral of the subterranean formation based on the fluid contact parameter.

14. The method of claim 13 , wherein the gas fluid has a gas saturation greater than about three percent in the portion of the fracture network.

15. The method of claim 13 , wherein the gas fluid includes one or more of carbon dioxide and nitrogen.

16. The method of claim 15 , wherein the fluid contact parameter is obtained based on an image of fracture zones within seismic resolution.

17. The method of claim 13 , further comprising:
determining a stimulated rock volume of the subterranean formation using the time-lapse difference by calculating difference between a processed baseline seismic survey and a processed monitor seismic survey acquired after injection of the gas fluid to obtain an image of a fractured stimulated rock volume.

18. The method of claim 13 , wherein the time-lapse difference is root mean square amplitude difference.

Assignees

• Conocophillips Co

Inventors

• Wheeler Thomas J
• Mutoru Jane W
• Keys Robert G
• Jurick Dana M
• Fissell Mark J

Classifications

• G01V1/308 Primary

  Time lapse or 4D effects, e.g. production related effects to the formation (fluid flow per se E21B47/00) · CPC title

• G01V1/34

  Displaying seismic recordings {or visualisation of seismic data or attributes} · CPC title

• G01V2210/6122

  Tracking reservoir changes over time, e.g. due to production · CPC title

• G01V2210/646

  Fractures · CPC title